Synchronous condenser
Synchronous machine with no shaft load, smooth variable Q via field control. Provides INERTIA + FAULT MVA that capacitors / SVC / STATCOM cannot. Modern comeback for low-inertia high-renewable grids and HVDC support.
Step 1 — Synchronous condenser: pure-Q machine
Reference notes
A synchronous condenser is a synchronous machine that operates with NO mechanical shaft load — used purely for reactive-power support. Use Next → to walk through Q control via field current, the case for synchronous condensers vs capacitor banks, the modern revival driven by low-inertia renewable-heavy grids, and the trade-off vs SVC and STATCOM.
What it is
- Synchronous machine running with P ≈ 0 (just losses).
- Construction identical to a generator: stator with 3-φ winding, rotor with DC field, AVR, protection.
- Variable Q output — from full-leading to full-lagging — set by field current via AVR.
- Often a retired generator with its turbine coupling removed, or a purpose-built machine.
Q control via field
Like any synchronous machine, the condenser obeys its V-curve — armature current vs field current at constant real power. At P = 0 the V-curve is purely the reactive characteristic:
- Under-excited (low I_f): E < V_t → stator current lags internally → machine ABSORBS Q from the grid (acts like a shunt reactor).
- Matched I_f: E = V_t → zero stator current → no Q exchanged.
- Over-excited (high I_f): E > V_t → stator current leads internally → machine GENERATES Q (acts like a shunt capacitor).
Synchronous condenser vs capacitor bank
| Property | Sync condenser | Capacitor bank |
|---|---|---|
| Q output | Continuously variable, both ± directions | Discrete steps, only +Q (generation) |
| Inertia contribution | YES — kinetic energy in rotor | None |
| Fault current contribution | YES — ~6× rated for 3-5 cycles | None |
| Harmonics | Sinusoidal fundamental only | Sinusoidal, but switching transients |
| Capital cost ($/Mvar) | ~4× capacitors | Cheapest reactive resource |
| Standby losses | ~1–3 % of rating | ~0.1 % |
Modern resurgence
After decades of decline, synchronous condensers are being deployed again for three reasons:
- Low-inertia grids — wind / solar IBRs have effectively zero rotational inertia. As IBR penetration rises past ~30–50 %, frequency excursions become sharper. Sync condensers provide real H — stored kinetic energy = ½·J·ω², where J is rotor moment of inertia and ω is shaft angular velocity at synchronous speed.
- Fault-current backup for IBRs — inverter-based generation typically contributes only ~1.2× rated current to faults (inverter-current limited). Protective relays calibrated for traditional 6× fault levels can lose selectivity. Sync condensers nearby restore fault MVA.
- HVDC inverter support — line-commutated HVDC inverters need a strong AC system (high short-circuit ratio) at their terminals. Sync condensers boost local SCR enough to allow the HVDC to run at higher capacity.
Coal-to-condenser conversions
Retired coal plants are increasingly being converted to sync condenser duty: decouple the turbine, leave the generator + AVR + transmission interconnection in place, add a starting mechanism. Result: large variable-Q resource at modest capital (~$30–50M for 600 MVAR vs ~$150M for new build). Eraring (600 MVAR, Australia, 2025) and Liddell (200 MVAR, Australia) are recent examples.
Starting
Like any synchronous machine, a sync condenser cannot self-start — the rotor must reach synchronous speed before the DC field is applied. Three methods:
- Pony motor — small induction motor on shaft (1–5 % of rating) spins the rotor up to near synchronous speed.
- Starting frequency converter — VFD-class drive ramps stator from 0 Hz to grid frequency over 30–60 s. Modern preferred method.
- Damper-winding induction start — connect to grid with field open, damper bars conduct, the rotor accelerates as an induction motor to ~95 % of synchronous speed, then field is energized and rotor pulls into synchronism. Limited to smaller units.
vs SVC and STATCOM
| Technology | Response | Inertia | Fault MVA | Cost |
|---|---|---|---|---|
| SVC (TCR + TSC) | ~30 ms | No | None | Low |
| STATCOM (VSC inverter) | < 10 ms | No | Limited (~1.2× rated) | Medium |
| Synchronous condenser | ~100 ms | YES | YES (~6× rated, 3-5 cycles) | High |
Modern best practice on weak grids: pair a sync condenser (inertia + fault MVA + steady reactive support) with a STATCOM (fast transient voltage control). Several Australian and US transmission projects in the 2020s use this combination.
V-Q curve
At fixed field, V_t vs Q is approximately linear with slope = −X_s (synchronous reactance per unit). Faster AVR = smaller effective droop = stiffer voltage support. Modern static excitation gives ~1–2 % effective V-Q droop after AVR settles.